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Abstract:

A method of treating a subterranean reservoir includes the steps of
delivering a stabilized, non-explosive combustible oxidizing solution
(COS) to a desired treatment area in the reservoir and activating the COS
with an activator which reduces the pH of the COS. Upon activation, the
COS reacts to produce sufficient heat and gas to stimulate the treatment
area.

Claims:

1. A method of treating a subterranean reservoir, comprising the steps
of: (a) delivering a stabilized, non-explosive combustible oxidizing
solution (COS) to a desired treatment area in the reservoir, (b)
activating the COS with an activator which reduces the pH of the COS,
wherein upon activation, the COS reacts to produce sufficient heat and
gas to stimulate the treatment area.

2. The method of claim 1 wherein the activator is either consecutively
injected after the COS, or is encapsulated in an emulsion with the COS.

3. The method of claim 1 wherein the treatment zone is a near well-bore
zone and/or a zone radially distal from the wellbore within the
reservoir.

4. The method of claim 1 wherein the COS comprises an aqueous solution
comprising: (a) a nitrate salt, (b) a nitrite salt, and (c) a stabilizer.

16. The method of claim 14 wherein the COS is nitrified or foamed prior
to placement in the treatment area.

17. The method of claim 8 wherein the activator is emulsified within the
COS, in a water-in-oil emulsion.

18. The method of claim 4 wherein the stabilizer comprises sodium
carbonate, a hydroxide, or a pyridine, combinations thereof.

19. The method of claim 1 wherein the COS is solids-free.

20. The method of claim 1 wherein the activator is encapsulated.

21. The method of claim 20 wherein the activator is encapsulated by a
three-phase emulsion, comprising an inner phase comprising the activator,
a middle phase comprising an oil, and an outer phase comprising the COS.

22. The method of claim 10 wherein the COS comprises a fracturing
proppant, and the COS is sufficiently viscous to transport the proppant
into the treatment area.

[0002] The present invention comprises thermo-gas-generating system and
methods for treating near-wellbore and radially extended treatment zones
in a reservoir formation to reduce restrictions to flow and increase the
production of the well.

BACKGROUND

[0003] Various methods for stimulating production in an oil or gas well
are well known in the art, including cleaning, perforating, and
fracturing techniques. It is known to use exothermic chemical gas
treatment to enhance production, both for a zone(s) within formation(s)
near the wellbore and/or zones radially distal from the wellbore. In one
example, gases are generated by the combustion of a gunpowder charge in
the wellbore, to increase the downhole pressure sufficient to fracture
the treated formation (Mischenko, I. Skvazhinnaya dobycha nefti. [Well
Oil Production]. Oil and Gas. Gubkin Russian State University of Oil and
Gas. Moscow. 2007, UDK 622.276.5, pg. 258). According to this method, a
powder charge is delivered downhole into position near the zone to be
stimulated using a wireline logging cable. Detonation of the powder
charge rapidly produces gases which stimulates the formation in the zone
of interest. This method using a gun powder charge has been used in the
oil and gas industry for many years, but has proved to have a limited
effect to stimulate the formation.

[0004] Another known method of near-wellbore formation stimulation is the
use of thermal acidizing stimulation. These methods use thermal energy
that is formed with the reaction of hydrochloric acid with magnesium
metal (Mischenko, I., pp. 253-256), which heats the acid solution and the
nearby formation, melting paraffin and other deposits that can then be
removed or produced from the wellbore. Any excess acid, not spent on
reaction with the magnesium, then dissolves and cleans the deposits,
aided by the increased wellbore temperatures. The removal of the deposits
and dissolved formation materials increases the fracture sizes and pore
throats that serves as a path for formation fluids to be produced. The
temperature increase is modest and is frequently not high enough to
effectively remove the paraffin and other deposits that restrict the
production of fluids from the formation. The reaction temperatures are
limited because cold 15-18% hydrochloric acid solution is flushed through
a layer of magnesium, and downhole temperatures do not increase to a
level to produce the favorable conditions for the reaction of the
hydrochloric acid with the formation materials or with the deposits.

[0005] Another similar method is to treat the formation near wellbore by
injecting an unstabilized suspension made from an emulsion of oil, dry
ammonium nitrate solution and magnesium granules into the near wellbore
formation. Once injected, the reaction is initiated by injecting an
activator into the near wellbore formation. The activator is typically a
hydrochloric acid aqueous solution (A.s. 640023, MPK 2 E21V43/24). The
hydrochloric acid solution reacts with the magnesium resulting in an
increase in the temperature of the acid. The temperature continues to
increase until decomposition of the ammonium nitrate is triggered and
additional thermal energy is created. Thermal energy is produced from the
reaction of magnesium and hydrochloric acid, decomposition of ammonium
nitrate, and also the combustion of hydrogen with oxygen liberated from
the nitrogen oxide reaction that occurs during the final stage of
treatment being pumped. During the final stage of the reaction, the
mixture of gases with hydrogen and oxygen may explode. This explosion has
significant energy and because it occurs near wellbore, the resulting
explosion can damage the integrity of well cement job, and compromise the
integrity of the entire well.

[0006] Another known method involves the injection of a combustible
oxidizing solution (COS) followed by a combustion activator, typically in
the form of pelleted aluminum and chromium oxide powder (Russian Patent
2,126,084), or pellets containing a mixture of sodium borohydride and
sodium dioxide (Russian Patent 2,154,733). The method is executed by
pumping consecutive stages of magnesium and proppant with a water-base or
oil-base fluid, COS and an acid solution (Russian Patent Application
2009/115,499).

[0007] These methods are disadvantageous because they require solid
particles which do not always penetrate into the treatment zone. As well,
there is a significant risk that the activation of the COS cannot be
controlled due to the uneven distribution of the solid particles in the
formation.

[0008] In another known method, a thermo-gas-generating solution (TGGS) is
used which contains an aqueous solution of ammonium nitrate, ammonium
chloride or diammonium phosphate. The TGGS is injected into the formation
to be treated, and a powder charge is used to initiate the combustive
reaction of the TGGS (Russian Patent 2,064,576). The main disadvantage of
the method is that the use of an explosive as an activator for initiating
the combustive reaction introduces operational complexity, and that the
explosive can cause damage to the casing, cement and other down-hole
equipment that may be present in the well.

[0009] Another known combustible oxidizing solution (COS) used for
exothermic chemical gassing treatment uses glycerin as the combustible
material (Russian Patent 2,100,583). However, the heat produced by this
solution is typically insufficient to effectively remove paraffin and
other deposits that restrict the productivity of the well in the wellbore
and the near wellbore formation. As well, there is a risk of an unplanned
reaction, which makes this form of treatment unsafe.

[0010] It is also known to use a chemical activator to initiate the
decomposition of a COS (Russian Patent 2,154,733, mpk E21V43/263). In
this case, an aqueous COS containing ammonium nitrate and a water soluble
organic fuel creates high bottom hole pressure by releasing gas from the
decomposition of the COS. The activator in this case is a pelleted
mixture of sodium borohydride or sodium tetrahydraborate (85-95% wt) and
sodium peroxide (5-15% wt). The activator is typically used at
concentration of 2-5% of the weight of the COS. This method may be
disadvantageous because the decomposition or combustion reaction may
occur too rapidly, causing a pressure increase that exceeds the safe
working limit and resulting in damage to the casing, wellbore cement and
other equipment in the wellbore. Despite this, this method does not
appear to produce sufficient pressure to fracture the formation and any
fractures that are created are of limited width and depth of penetration
in the formation. Furthermore, the use of a pelleted activator to
initiate the reaction requires a special delivery device or technique.

[0011] Therefore, there is a need in the art for a system or method which
may mitigate some or all of the limitations of the prior art.

SUMMARY OF THE INVENTION

[0012] In one aspect, the invention comprises a method of treating a
subterranean reservoir, comprising the steps of:

[0013] (a) delivering a stabilized, non-explosive, solids-free combustible
oxidizing solution (COS) to a desired treatment area in the reservoir,

[0014] (b) activating the COS with an activator, wherein upon activation,
the COS reacts to produce sufficient heat and gas to stimulate the
treatment area.

In one embodiment, the activator is either consecutively injected after
the COS, with or without a spacer slug of oil or water, or the activator
may be encapsulated in an emulsion with the COS. The treatment area may
be a near-wellbore zone and/or a zone radially distal from the wellbore
within the reservoir. The distal zone may be several hundreds of meters
from the wellbore.

[0015] In one embodiment, the COS comprises an aqueous solution of
reactants comprising ammonium nitrate, preferably in a weight percent
(w:w of the total composition) range of about 15.0-50.0%, sodium nitrite
(preferably 15.0-40.0 wt %), and a stabilizer (preferably 0-2.0 wt %),
with water (to 100% total).

[0016] In one embodiment, herein referred to as the BSS system, the COS
may comprise an oil-in-water or water-in-oil emulsion, and may further
comprise an oil such as produced crude oil (preferably 10.0-25.0%) and an
emulsifier (preferably 0.1-2.0%). The activator may comprise an aqueous
inorganic acid solution such as hydrochloric acid.

[0017] In another embodiment, herein referred to as the BSV system, the
COS further comprises a viscosifier (preferably 0.1-0.5%), such as guar
gum, a viscosifying surfactant or a polyacrylamide. The activator may
comprise an organic acid solution, such as acetic acid. The activator may
be emulsified with an oil, such as produced crude oil.

[0018] In any embodiment, the stabilizer may comprise sodium carbonate
(soda ash), a hydroxide, quinolone, or a pyridine, or combinations
thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

[0019] In the drawings, like elements are assigned like reference
numerals. The drawings are not necessarily to scale, with the emphasis
instead placed upon the principles of the present invention.
Additionally, each of the embodiments depicted are but one of a number of
possible arrangements utilizing the fundamental concepts of the present
invention. The drawings are briefly described as follows:

[0020] FIG. 1 shows a graph of kinetics of temperature growth (degrees
Celsius) over time (minutes) of a BSS COS solution after activation.

[0021] FIG. 2 shows a graph of heat release rate (milliWatts/grams of COS)
over time (minutes) of a BSS COS after activation.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

[0022] The invention describes a method to be used in the oil and gas
service industry to stimulate oil and gas bearing formations both near
wellbore (within several meters of the wellbore), and to several hundreds
of meters radially from the wellbore. The invention can be used under
normal and low reservoir pressures to improve the effective formation
permeability of the near wellbore zones and increase the production of
petroleum and natural gas wells. It is believed that the primary
mechanism of stimulation is to extend and improve either or both
naturally occurring formation fractures and induced fractures from other
stimulation operations such as hydraulic fracturing. Furthermore,
embodiments of the invention are capable of generating sufficient energy
to create new formation fractures both near wellbore and deep within the
formation to increase the flow and cumulative production of oil and gas
from a wellbore. The reaction is intended to be non-explosive and does
not requires a detonating charge to initiate the reaction results, and is
therefore intrinsically safer than prior art that uses explosive
reactions and detonations. Embodiments of the invention may also improve
the injectivity of a fluid into a reservoir.

[0023] The chemical reactions which take place in the methods described
herein produce a significant volume of gas and thermal energy that are
useful independently, or can be used to enhance or supplement existing
treatment technologies to increase the productivity of a well. In one
embodiment, the rate of reaction can be controlled to generate a
significant volume of gas in a short amount of time, ranging from
microseconds to minutes. Under certain reservoir conditions, it is
possible to customize the reaction rate to release a gas volume at a rate
sufficiently high enough to extend and improve existing natural formation
fractures, and also to induce additional fractures into the formation,
further increasing the effective permeability of the formation. The heat
and gas generated from the reaction decreases the viscosity and swells
the formation fluids thereby improving the mobility of the formation
fluids.

[0024] In one aspect, the invention comprises a stabilized, non-explosive
combustible oxidizing solution (COS), which undergoes a chemical gassing
exothermic reaction upon activation. In one embodiment, the COS comprises
an aqueous solution comprising a nitrate salt and a nitrite salt that
will react to produce thermal energy and gas. The nitrate salt may
comprise ammonium nitrate. The nitrite salt may comprise sodium nitrite.
The COS solution is stabilized with a stabilizer to prevent the reaction
from occurring prior to activation, and to control the rate of the
reaction after activation. The stabilizer may comprise a substance that
increases the pH of the COS above about 5.0. Suitable stabilizers may
include sodium carbonate (soda ash), potassium carbonate, potassium
hydroxide, sodium hydroxide, pyridine, quinoline, or combinations
thereof. The choice and quantity of stabilizer may be chosen to vary the
threshold at which the reaction commences, and/or the reaction rate.

[0025] Without restriction to a theory, it is believed that at a
sufficiently low pH, the components of the COS decompose to produce gas
which is predominately or entirely nitrogen gas, in a series of complex
exothermic reactions. An activator which reduces the pH of the COS, such
as an inorganic or organic acid, is used to initiate the reaction. In one
embodiment, the activator comprises hydrochloric acid, acetic acid,
propionic acid, formic acid, sulphamic acid, or combinations thereof. The
quantity or strength of the activator can be adjusted to also affect the
rate of the reaction. To initiate the reaction, the activator only needs
to contact a fraction of the COS. Once initiated, the COS will continue
to react and fully decompose in a continuous reaction that proceeds
without the addition of more activator. This continuous reaction of the
COS will continue until either all the COS components have fully reacted,
or the reaction is quenched by increasing the pH of the COS.

[0026] In another embodiment, the activator may comprise a salt which
reacts with and consumes the stabilizer. Suitable examples may include
chloride salts such as ferric or ferrous chloride, or cupric or cuprous
chloride.

[0027] In one embodiment, the invention comprises the step of pumping a
pre-blended stabilized COS into a wellbore, delivering it to a treatment
area, and activating it with an activator to create an exothermic
chemical gassing system (ECGS). The rate of energy production and
quantity of energy can be controlled by both the chemical components and
by the pumping procedures. The activator may be delivered sequentially,
or may be delivered with the COS in an encapsulated or otherwise
segregated form.

[0028] In one embodiment, the ECGS comprises a low viscosity aqueous
ammonium nitrate and sodium nitrite solution in an oil-continuous
emulsion, referred to herein as BSS. The oil may comprise produced crude
oil, or a fuel oil such as diesel. In another embodiment, the ECGS
comprises a controlled viscosity aqueous ammonium nitrate and sodium
nitrite solution which includes a viscosifier, herein referred to as BSV.
The BSV system physical properties, such as density and viscosity are
highly customizable, such as by foaming the BSV with the injection of
high pressure nitrogen. Both the BSS and BSV reactions may be initiated
by pumping of an activator into the same formation treatment area
containing the injected BSS or the BSV.

[0029] The reaction is initiated upon contact by the activator with the
BSS or BSV COS. Once initiated, the reaction rate rapidly accelerates,
resulting in the release of a significant amount of gas and heat in the
treatment area of the formation. This rapid generation of heat and gas
stimulates the formation and has been demonstrated in field trials,
described below, to increase production. Without restriction to a theory,
it is believed that well stimulation occurs through three primary
mechanisms:

[0030] 1. The rapid release of gas increases the pressure
in the formation pore space and causes existing natural fractures to
extend, existing fractures to widen, and create new fractures.

[0031] 2.
The thermal energy created from the reaction heats the surrounding
fluids, causing thermal expansion, while the elevated temperature reduces
the viscosity of the oil in the formation, promoting its flow.

[0032] 3.
The superheated gas produced by the reaction reacts with flow restricting
deposits, such as asphaltenes and paraffins, to partially or completely
remove such deposits from the formation pore space and to allow fluids to
flow more freely in the formation.

[0033] Both the BSS and BSV systems comprise a combustible oxidizing
solution (COS) comprising water and a nitrate salt, such as ammonium
nitrate, and a nitrite salt, such as sodium nitrite. Both the BSS and BSV
systems comprise components that will generate heat and gaseous products
when a reaction is initiated with the acidic activator.

[0034] The BSS system utilizes an emulsion to create viscosity, but may
also use the different phases of the emulsion, such as the outer or
continuous phase and the inner or discontinuous phase, to segregate or
encapsulate the reactive components in an emulsified fluid. In one
embodiment, the BSS COS is prepared as an oil continuous phase emulsion,
with the discontinuous phase being an aqueous ammonium nitrate, sodium
nitrite and stabilizer solution, with an emulsifier added for the
preparation of the emulsion. The COS emulsion is injected into formation,
followed by the activator made of an inorganic acid aqueous solution,
such as a hydrochloric acid. In one embodiment, and depending in part on
the strength of the acid, the volume of the activator pumped may be at a
ratio of about 1:1 BSS COS:activator, up to about 3:1 BSS COS:activator.

[0035] Like other well stimulation techniques, where an emulsion is used
to create viscosity, the BSS emulsion may be specifically placed or
directed to high permeability and naturally fractured formations. For
example, the BSS emulsion may be injected and result in increased
production from depleted highly fractured carbonate oil bearing
formations, with bottom hole pressures of less than 1,000 kPa (145 psi).

[0036] In one embodiment, the BSS system may also implement the use of
multiple continuous and discontinuous phases to encapsulate the
reactants, as well as to encapsulate the activator. In one embodiment, a
three-phase water-in-oil-in-water emulsion may be used where an inner
phase comprises an aqueous activator such as a hydrochloric or acetic
acid solution, a middle phase comprises an oil such as a produced crude
oil or a fuel oil such as diesel, and an outer phase comprises the COS.
This three-phase emulsion may obviate the need to pump a separate
activator stage to initiate the reaction.

[0037] To initiate the reaction in the three phase emulsion, the activator
in the inner phase would need to contact the COS in the outer phase
through some environmental change which causes de-emulsification, such as
a change in pH, temperature, ionic strength or mechanical energy like a
change in pressure. As the emulsion begins to break, the activator and
COS make contact and react to produce heat and gas. The middle oil phase
may further fuel the reaction by oxidizing to produce additional heat and
gas. The reaction continues to accelerate as the heat and gas further
breaks the emulsion, causing a continuous reaction to proceed until all
the reactants are consumed, or the pH of the system is increased to
terminate the COS reaction, which is pH sensitive.

[0038] In one embodiment, the BSS system contains the following components
(w/w %):

[0041] In one embodiment, the BSV COS comprises an aqueous solution
comprising ammonium nitrate, sodium nitrite, and a stabilizer. The BSV
COS is viscosified with a viscosifier, such as guar gum, polyacrylamide
or a viscosifying surfactant, to achieve the desired viscosity. The
viscosity of the COS can be customized by varying the amount or type of
viscosifier. If the BSV is required to have a high viscosity, a
cross-linked viscosifier may be used. By controlling the viscosity, the
BSV may be used in different applications, including using the BSV COS as
a hydraulic fracturing fluid to carry proppant into a fracture.
Additionally, high viscosity BSV fluids can be used in high permeability
formations, such as highly fractured formations and/or depleted reservoir
pressure formations, where less viscous fluids would be less effective
for stimulating the well. Conversely, in low permeability or tight
formations where a low viscosity fluid is desirable, the viscosifier can
be reduced or omitted from the BSV system to lower the viscosity close to
that of water.

[0042] Once the COS solution with the desired viscosity is injected into
the treatment area of the formation, an activator is injected into the
same treatment area. For the BSV system, in one embodiment, the activator
comprises an aqueous organic acid solution, and may further comprise an
oil, such as produced crude oil or a fuel oil such as diesel, which may
optionally be emulsified. In one embodiment, the organic acid may
comprise acetic acid. This activator solution or emulsion is then
injected into the same treatment area with the previously injected BSV
COS to initiate the exothermic chemical gassing reaction. Since the
activator for the BSV system is made from an organic acid, such as acetic
acid, the BSV system is safe for use in wells containing tubulars and
other components made from stainless steel and nickel alloys, where
conventional stimulation methods using a hydrochloric acid solution can
damage these well components.

[0043] In one embodiment, the BSV system contains the following components
(w/w %):

[0046] The BSS and BSV systems both comprise components that are readily
available and used in other applications. The methods of their use
comprise relatively convenient and easy preparation steps due to simple
and quick mixing procedures for the solution. The components present well
understood health, safety and environmental risks, and there are
well-known methods to minimize such risks. To increase safety of surface
handling of the COS, the risk of an unexpected reaction at surface can be
lowered by increasing the pH through the addition of a stabilizer such as
soda ash. The system is compatible with encapsulation technology and
methods, such as an encapsulated activator, that could enhance the
functionality and customizability of the system.

[0047] If an organic acid is used, the compositions are relatively
non-corrosive and can be used with well completion components containing
stainless steel and nickel alloys that are sensitive to other stimulation
fluids containing strong inorganic acids. Both systems are capable of
injecting stimulating fluid deep within the formation to reduce the risk
of negatively impacting the wellbore integrity and allowing for greater
treatment coverage in the formation to maximize the incremental
production.

[0048] There is virtually no risk of sedimentation of the systems because
they do not use any solids that could precipitate, bridge off and
restrict the injection of the fluid or flow back of fluid from the
formation. Also, because of the lack of solids in the system, there is
little risk of erosion and material loss of wellbore components. In
alternative embodiments, a non-reactant solid may be added as a hydraulic
fracturing proppant.

[0049] The rate of reaction can be controlled to optimize the treatment
objectives, such as maximizing the thermal output of the reaction or
maximizing the rate and amount of gas generated. By customizing the
reaction to produce the desired amount of heat and gas specific well
treatment objectives can be achieved. For example, if the treatment
objective is to remove deposits such as paraffin, then more heat and less
gas from a slow rate of reaction over several hours may be desired. If
the treatment objective is to create additional formation fractures deep
within the formation the desired reaction may be to maximize the volume
of gas generated with a fast rate of reaction over a few seconds or
minutes. The sensitivity threshold to initiate the decomposition can be
controlled to meet the specific reservoir conditions, such as reservoir
temperature.

[0050] In one embodiment, the system may feature customizable fluid
rheology. The viscosity of the system can be controlled from essentially
that of water to several hundred centipoises, which may allow the system
to be used in a conventional hydraulic fracturing application. In one
embodiment, the viscosifier may be crosslinked utilizing the same pH
sensitivity of the COS. The density and fluid rheology of the system can
also be controlled through the use of nitrogen gas injection into the COS
to produce a two phase fluid, such as a nitrified or foamed fluid.

[0051] In operation, and in one embodiment, for the safe and effective use
of the BSS and BSV systems to successfully treat a well, the downhole
temperature of the treatment zone should be about 60° Celsius or
greater. At temperatures above 60° C., the reaction will generate
gas at a rate (cubic meters per second) sufficient for the treatment to
be effective. However, below 60° C., the reaction rate may not be
sufficient, and it may become necessary to inject acid accelerators or
additional activators, or reduce the amount of stabilizer in the COS, to
ensure that the rate of the reaction and gas generation is adequate for
the treatment.

[0052] By using different stabilizers at varying quantities, the system
can be made stable at ambient temperatures (20 to 25° C.) for
several days to facilitate greater flexibility in handling the fluids.
The COS is controlled and stabilized by increasing the pH level of the
COS at ambient temperatures. When at a pH higher than about 5 and with a
suitable stabilizer, the COS is very stable and will not degrade at
ambient temperatures. In these conditions, the COS can be stored for
several days. If the COS is heated to 50° C. within 30 minutes, it
will still remain stable, with only an insignificant amount of gas being
generated. Furthermore, after heating to 50° C., the COS continues
to remain stable for some time.

[0053] This specification describes various examples of the claimed
invention. Although the invention has been described in language specific
to features of a composition and/or acts in a method, the invention is
defined in the claims, and is not necessarily limited to the specific
features or acts, or combinations of features and acts described, which
are only intended to be exemplary implementations of the claimed
invention. The following examples are intended to exemplify embodiments
of the invention, and should not be looked at to narrow the claimed
invention unless specifically claimed in that fashion.

EXAMPLE 1

Laboratory Testing Rates of Reaction--BSS

[0054] The chemical reaction of the sodium nitrite with ammonium nitrate
generates nitrogen gas, water and heat, and has a rate of reaction that
is pH dependent on a number of equilibrium processes. In laboratory
testing, the pH of a COS solution was increased with sodium carbonate
(soda ash), and the pH was decreased with hydrochloric or acetic acid.

[0055] Laboratory samples of BSS COS were prepared using a well-known
commercially available emulsifier, as follows. A COS discontinuous phase
was prepared by mixing ammonium nitrate (25.0-40.0 g), sodium nitrite
(15.0-30.0 g) and water (30.0-50.0 g), which was then heated to
50° C. The solution had a density of 1.13 to 1.39 g/cm3.

[0056] To this solution, soda ash (2.0-10.0 g) and pyridine (0.01-1.0 g)
were added and mixed to stabilize the solution. The solution was then
emulsified with produced crude oil (8.0 to 30.0 g) and an emulsifier
(0.01-1.0 g) at room temperature, in an agitator at 2,400 to 2,500 rpm
for 3 to 4 minutes.

[0057] The reactive capacity of this BSS COS emulsion with the addition of
an activator to initiate the decomposition reaction was assessed as
follows. Approximately 40 g of the BSS COS emulsion was put into a test
tube with a diameter of 30 mm and between 10 g to 20 g of 10% to 30%
hydrochloric acid aqueous solution was added to the test tube. The
capacity of the reaction was determined visually by observing the
emission of gases and measuring the changes to the temperature, which
were measured by a thermocouple submerged into the reactive mass with the
digital output displayed and recorded on a computer. A significant
release of gases and an increase in temperature were observed. The
results of the BSS system reactions are presented in the Table 1 and in
FIGS. 1 and 2. Table 1 shows the temperature over time and demonstrates
how the reaction creates a significant amount of heat. FIG. 1 show the
temperature growth over time, heat release rate and released heat of the
reaction. Table 1 and FIGS. 1 and 2 shows the results of the analysis of
the BSS exothermic chemical gassing composition in terms of the heat
release rate in the adiabatic mode.

[0058] BSV is a high viscosity, aqueous COS with the desired viscosity of
the system being achieved from the addition of guar gum (GG) or
polyacrylamide (PAA) to the COS. To stabilize the COS, an aqueous soda
ash solution was added to the COS.

[0059] Laboratory samples of the viscous BSV COS were prepared (% total
weight) by mixing, ammonium nitrate (15.0-50.0%), sodium nitrite
(15.0-40.0%) and water (up to 70.0%). To this solution, soda ash (up to
1.5%) stabilizer was added and mixed, to create a homogeneous solution.
To this solution, guar gum (up to 1.0%) was added and stirred at
30° C. The resulting solution was viscous and homogeneous.

[0060] The reactive capacity of this viscous BSV COS with the addition of
an activator to initiate the decomposition reaction was assessed as
follows. Approximately 100 ml of viscous BSV COS was put into an
insulated flask with the diameter of 45 mm, and a thermometer was set
into the solution, and the initial temperature recorded. The following
aqueous activator solutions were prepared:

[0061] a. AA--acetic acid

[0062] b. FA--formic acid

[0063] c. PA--propionic acid

[0064] d.
SA--sulphamic acid

[0065] e. GG--guar gum

[0066] f. PAA--polyacrylamide

[0067] The aqueous activator solution was mixed with produced crude oil,
which may or may not form an emulsion. The oil and activator solution or
emulsion was added to the COS but not stirred, and the temperature
recorded. The reaction was monitored by the intensity of the gas released
and the changes in temperature over time. Various combinations of
activator, oil and COS where experimented with. The volumes of the
various combinations and the observations for the reactions were recorded
in Table 2.

[0068] The treatment method of using a BSS exothermic chemical gassing
system includes the injection of an emulsion comprising a continuous oil
phase with a discontinuous Combustible Oxidizing Solution (COS) phase.
The emulsion was prepared and pumped down the wellbore, followed by a
spacer fluid of either oil or water to displace the COS emulsion out of
the wellbore and place it into the treatment area of the formation. The
BSS activator aqueous hydrochloric acid solution was then pumped into the
wellbore and then displaced from the wellbore and into the treatment area
with water.

[0069] Mixing of injected COS and activator in the formation pore spaces
and fractures causes initiation of the decomposition reaction that
generates of a vast amount of heat and gases, as confirmed in the
laboratory tests. The gases generated during the reaction inside the
fractures and pore spaces created pressure which expand the existing
fractures and create new fractures in the formation, thus creating new
paths for petroleum and natural gas to flow into the wellbore. An
increase in temperature further expands the gas and further increases the
downhole pressure and temperature, accelerating the decomposition of the
COS and continuing to increase the temperature.

[0070] The first stage of a field trial was to prepare the COS by pumping
4,800 liters into a 10 m3 mixing tank and heating to about 45 to
50° C. with a steam truck. While continuously circulating the
heated water, 190 kg of soda ash was added and dissolved, followed by
3,900 kg of ammonium nitrate. To this solution and while continuing to
circulate, 2,700 kg of sodium nitrite was added to the mixing tank. The
density of the prepared COS solution was 1.32 g/cm3.

[0071] The second stage is to create a continuous oil phase emulsion by
mixing 4.0 m3 of produced crude oil and 9.4 m3 of the prepared
COS, with an emulsifier to prepare a total volume of the emulsion of 13.5
m3.

[0072] At the third stage, the entire volume of the emulsion was pumped
into the wellbore. Then 1.0 m3 of oil spacer was pumped into the
wellbore, followed by the BSS activator which comprised 5.6 m3 of
12-14% hydrochloric acid aqueous solution. A displacing volume (10
m3) of produced water was then pumped into the wellbore.

[0073] The well production before treatment was 2 tonnes/day of oil. The
well production after the treatment had been completed and downhole
equipment had been installed reached 7-9 tonnes/day of oil.

EXAMPLE 4

Field Trial of BSV System

[0074] The treatment method of using the BSV system includes the injection
of a high viscosity aqueous ammonium nitrate and sodium nitrite with
stabilizers. The high viscosity COS is displaced from the wellbore with a
spacer of either oil or water to displace the viscous COS out of the
wellbore and into the treatment area of the formation. The BSV activator
aqueous organic acid, such as acetic acid, and oil solution is then
pumped into the wellbore and displaced with water into the same treatment
area.

[0075] Mixing of the viscous COS and activator solution in the formation
pore spaces and fractures initiates a reaction accompanied by the release
of a significant amount of heat and gases. The gases generated during the
reaction in the formation increases the downhole pressure to expand
fractures and induce new fractures in the formation, thus creating new
paths for petroleum and natural gas to flow into the wellbore. An
increase in temperature expands the gases and further increases the
downhole pressure and temperature, further accelerating the decomposition
of the ammonium nitrate and continuing to increase the temperature.

[0076] The field trial of the BSV system was executed as follows. The
first stage was to prepare the COS by pumping 5,200 liters of water into
a 10 m3 mixing tank which was then heated to 45 to 50° C.
with a steam truck. While continuously circulating the heated water, 170
kg of soda ash was added and dissolved, followed by 5,100 kg of ammonium
nitrate and 10 kg of polyacrylamide. To this solution and while
continuing to circulate, 3,300 kg of sodium nitrite and 30 liters of
additional pyridine stabilizer was added to the mixing tank. The density
of the prepared COS solution was 1.38 g/cm3.

[0077] The second stage is to separately prepare the organic acid-in-oil
BSV activator emulsion. In a separate mix tank, 4,800 liters of oil, 15
liters of emulsifier and 950 liters of 70% acetic acid aqueous solution
was continuously circulated and mixed to create a continuous oil phase
emulsion.

[0078] At the third stage, 10.0 m3 of the viscous COS was pumped into
the wellbore. Then a 1.0 m3 volume of oil spacer was pumped into the
wellbore, followed by the 5.8 m3 of the BSV activator emulsion.
Finally, a displacing volume of 20 m3 of produced water was pumped
in to the wellbore.

[0079] The well production prior the treatment was 2 tonnes/day of oil.
The well production after the treatment was completed and downhole
pumping equipment had been installed reached 10-12 tonnes/day of oil.